Ever since the commercial use and production of liquid hydrocarbons commenced in the mid-19th century, scientists have pursued ways of economically extracting hydrocarbons from organic-rich rocks such as oil shale. Historically and currently, almost all hydrocarbons are produced from subterranean reservoir strata and formations. Such hydrocarbon-bearing reservoirs, containing natural gas and/or oil, typically comprise permeable and porous rock such as sandstone or limestone (carbonate). Frequently, these types of rocks serve as traps for hydrocarbons and can be commercially exploited as oil or gas reservoirs. Once penetrated by a well, reservoir strata may be able to produce hydrocarbons in commercial quantities. Occasionally, well treatment techniques such as fracturing or acidizing will be needed to enhance or accelerate production from these reservoirs.
Reservoir strata and formations such as sandstone and carbonate are not, however, the original source of the hydrocarbons. The reservoirs are usually the rocks into which the hydrocarbons have migrated over geologic time. The actual so-called “source rocks” are the organic-rich rocks from which the hydrocarbons originally derive. A common source rock is shale which contains a hydrocarbon precursor known as kerogen. The kerogen is a complex organic material that is the product of the initial biologic organic matter that was buried with the soils and clays which ultimately formed the shale rocks. The kerogen is generally tightly bound within the rock and only gets converted to hydrocarbons when it is exposed to temperatures over 100° C., typically under deep burial. This process is extremely slow and takes place over geologic time. Eventually, under the right conditions, the hydrocarbons within the shale or other source rocks will migrate (often through natural fissures, fractures and faults) until they reach a reservoir trap such as a sandstone or carbonate formation.
Source rocks that have yet to liberate their kerogen in the form of hydrocarbons are known as “immature” source rocks. These immature source rocks, however, contain the overwhelming majority of buried organic matter in the earth's crust. It is estimated that less than 1% of the organic matter is in the form of is hydrocarbons contained in reservoir rocks. The great majority is still present as kerogen and thus represents a vast untapped energy source.
Unfortunately, kerogen is not readily liberated from shale or other source rocks. Kerogen-bearing rocks near the surface can be mined and crushed and, in a process known as retorting, the crushed shale can then be heated to high temperatures which convert the kerogen to liquid hydrocarbons. Commercial and experimental mining and retorting methods for producing hydrocarbons from shale have been conducted since 1862 in various countries around the world. In the 1970s and 1980s several oil companies conducted pilot plant shale oil operations in the Piceance Basin of Colorado where large, high-quality reserves of oil shale are located. A more current project is the Stuart Oil Shale Project in Australia which uses a rotating retort to heat the shale to 500° C. There are a number of drawbacks to surface production of shale oil which has made its production more costly compared to conventional hydrocarbon production. These drawbacks include the high costs of mining, crushing, and retorting the shale and the environmental cost of shale rubble disposal, site remediation, and clean operation of the retort and associated plant.
Because of the high costs associated with surface shale oil production and because most of the shale is located at depths too deep to mine, attempts have been made to produce shale oil using in situ processes. In situ processing eliminates the costs associated with the mining, crushing, handling and disposal of the shale rock. Techniques for in situ retorting of oil shale were pilot tested with Green River oil shale in Colorado in the 1970s and 1980s. With the in situ process the oil shale is first rubblized into large fragments with explosives and then the kerogen is subjected to in situ combustion by air injection into the shale formation. In pilot operations by Occidental Petroleum and Rio Blanco in the 1970s and 1980s, air was injected at the top of the rubblized zone. The oil shale was then ignited, and the combustion front moved downward through the zone. Retorted oil drained to the bottom of the zone and was collected. In a different pilot project designed by Geokinetics, air was injected into wellbores at one end of the rubblized zone and the combustion front moved horizontally. The shale was retorted ahead of the combustion front and the resulting oil again drained to the bottom of the rubble and was produced from wells located at the opposite end of the rubblized volume.
A variation on the usual process for in situ conversion of rubblized oil shale utilizes hot flue gases from underground coal conversion. In this proposed process, a shallow shale bed is rubblized in preparation for a horizontal retort. In situ gasification and combustion are established in a nearby coal formation separated from the oil shale by a “barren” formation (so that combustion does not start in the rubblized oil shale). Hot, inert flue gases from the coal conversion are delivered to one end of the rubblized shale bed through a well that links the coal formation to the shale formation. The hot flue gases pass horizontally through the rubblized shale bed, retorting the oil shale, and sweeping the shale oil to production wells. Operating periods are estimated to be about 20 days. As with other in situ oil shale retorts, the shale rubblization involved in this process limits it to very shallow depths.
U.S. Pat. No. 5,868,202 describes a process for using an adjacent “source” aquifer or fracture to deliver an extracting fluid containing fuel and oxygen to an oil shale. The ignited extracting fluid migrates under pressure through the shales, extracting thermal energy, hot gases, or hydrocarbons. The extraction products migrate into an adjacent “sink” aquifer from which they are produced. This process is very difficult to manage because it requires a controlled flow of the extracting fluid through the oil shale.
Other in situ processes have involved directly heating the oil shale other than by combustion. Some attempts have been made to use microwave or other electromagnetic heating to heat the source rocks. A more direct approach, initially developed in Sweden, relied on thermal conduction from heated wellbores. The most recent of these processes utilized heat generated by either electrical resistance or gas-fired heaters to raise wellbore temperatures up to 600° C. With test wells spaced 0.6 m apart, the shale formation reached temperatures of about 300° C. and produced oil. However, with this method, spacing of the wells is extremely close and many wells would be required to achieve commercial production volumes of hydrocarbons.
Overall, the various in situ processes for producing oil shale have been commercially unattractive. Therefore, what is needed is an in situ method that effectively converts kerogen to producible hydrocarbons such that kerogen-bearing shale formations can become commercially exploitable.